The present disclosure relates to enhancing complex fracture networks in subterranean formations, and, more particularly, to enhancing complex fracture networks in the far-field region of the subterranean formation.
Hydrocarbon producing wells (oil producing wells, gas producing wells, and the like) are often stimulated by hydraulic fracturing treatments. In traditional hydraulic fracturing treatments, a treatment fluid, sometimes called a carrier fluid in cases where the treatment fluid carries particulates entrained therein, is pumped into a portion of a subterranean formation (which may also be referred to herein simply as a “formation”) at a rate and pressure sufficient to break down the formation and create one or more fractures therein. As used herein, the term “treatment fluid” refers generally to any fluid that may be used in a subterranean application in conjunction with a desired function and/or for a desired purpose. The term “treatment fluid” does not imply any particular action by the fluid or any component thereof.
Typically, particulate solids, such as graded sand, are suspended in a portion of the treatment fluid and then deposited into the fractures. The particulate solids, known as “proppant particulates” or simply “proppant” serve to prevent the fractures from fully closing once the hydraulic pressure is removed. By keeping the fractures from fully closing, the proppant particulates form a proppant pack having interstitial spaces which act as conductive paths through which fluids produced from the formation may flow. The degree of success of a stimulation operation depends, at least in part, upon the ability of the proppant pack to permit the flow of fluids through the interconnected interstitial spaces between proppant particulates.
In the case of stimulating low permeability formations, such as shale reservoirs or tight-gas sands, increasing fracture complexity, as opposed to proppant pack conductivity, during stimulation may further enhance the production of the formation. Low permeability formations, such as those described herein, tend to have a naturally occurring network of multiple, interconnected fractures referred to as “fracture complexity.” As used herein, the term “low permeability formation” refers to a formation that has a matrix permeability of less than 1,000 microDarcy (equivalent to 1 milliDarcy). As used herein, the term “ultra-low permeability formation” refers to a formation that has a matrix permeability of less than 1 microDarcy (equivalent to 0.001 milliDarcy).
As used herein, the term “fracture network” refers to the access conduits, man-made or otherwise, within a subterranean formation that are in fluid communication with a wellbore. The complexity of the fracture network (or “network complexity”) may be enhanced by stimulation (e.g., fracturing) operations to create new or enhance (e.g., elongate or widen) existing fractures. In some cases, the newly formed fractures may remain open without the assistance of proppant particulates due to shear offset of the formation forming the fractures (i.e., the formation in which the fracture is formed does not close perfectly, thereby leaving channels). In other cases, the fractures may be held open by proppant particulates or varying sizes, depending type of fracture (i.e., depending on the size of the fracture). The inclusion of proppant particulates in the fractures—new or natural—may increase the conductivity of a low permeability formation.